modeling polymer flooding, surfactant flooding and...

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Modeling Polymer Flooding, Surfactant Flooding and ASP

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Surfactant Flooding and ASP (Alkaline, Surfactant, and Polymer) Flooding with ECLIPSE

Charles A. KossackSchlumberger Advisor

Charles A. (Chuck) Kossack

• Education – University of Michigan - BS Chemical

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Engineering, BS Math– Stanford University - MS, Ph.D.

Chemical Engineering• Research Engineer at ARCO - 12

Years

April 11 NTNU-Seminar 2

Years– Developed reservoir simulators– Applied simulators

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• Professor Norwegian Institute of Technology (now NTNU) – 4+ Years

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– Compositional Simulation– Scale-up Process– Simulating Horizontal Wells


• Independent Consultant – 5+ Years– Norsk Hydro - Oslo, Norway


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– AGIP - Milan, Italy– BEB - Hanover, Germany

• Schlumberger - 15+ Years– GeoQuest:ECLIPSE Support– Consulting with GeoQuest Reservoir


gTechnologies- Holditch-Reservoir Technologies - Now SIS Training and Development

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• Courses Taught– Applied Reservoir Simulation

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– Equation Of State and PVT Analysis– Compositional Simulation, Theory and

Applications– Simulation of Naturally Fractured

Reservoirs


Reservoirs– Computer Aided History Matching Using

SimOpt


• Courses Taught– Thermal Reservoir Simulation Using

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ECLIPSE– Integrated Reservoir Simulation– ECLIPSE Workflow Project Course– Simulation of In-situ Combustion and

Chemical Reactions Using ECLIPSE


Chemical Reactions Using ECLIPSE– Simulation of Enhanced Oil Recovery

Processes

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Seminar Topics

• Simulation of Polymer Flooding With ECLIPSE

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• Simulation of Surfactant Flooding With ECLIPSE

• Simulation of ASP Flooding With ECLIPSE


Disclaimer

• Each one of these subject is complex and would require 3-5 day class to

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cover all details.• 100’s of keywords are involved.• Only overview of theory and

ECLIPSE models will be given here.


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Copies

• Copy of this presentation• And datasets used in examples

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p• Available – check with Professor Kleppe


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Introduction


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Cost of EOR FluidsSchlum

berger Public


ECLIPSE Blackoil

Polymer

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Polymer

Surfactant

Alkaline

Foam


Solvent

Extensions (Salt models,Multi-partitioned tracers)

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Sector Model for Demo Simulations

• Example simulations for all processes will be run in a

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heterogeneous sector model.• Random heterogeneity in

permeability and porosity will increase mixing and break down the injected slug of chemicalsinjected slug of chemicals.


Source of porosity-permeability correlation for heterogeneities of sector model grid.

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Stochastic porosity has uniform density in range

3.015.0 ≤≤φ


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Grid

• 30 x 30 x 4 grid• Some dataset in FIELD unit, some in

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,METRIC units.

• Will usually compare Recovery Factors (RF) – FOE


Porosity Values

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NTNU-Seminar 16

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Permeability Values (Log Scale)Schlum

berger Public

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Oil Saturation at 40% of Surfactant Injection Case

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Surfactant Adsorbed at End of Simulation

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Water Wet and Oil Wet Rel Perms for Exercise Simulations

0.8

1

krw oil wet

krow oil wet

k t t

krow water wet

krw oil wet

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0.2

0.4

0.6

Krw

and

Kro

w

krw water wet

krow water wet

krw water wet

krow oil wet


00.2 0.25 0.3 0.35 0.4 0.45 0.5 0.55 0.6

Saturation of Water

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Initial Conditions

• Water flooded reservoir – Swi = 0.55• Unless otherwise specified

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p• Oil viscosity = 2 cP• Water viscosity = 0.34 cP


Theoretical Discussion:

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Langmuir EquationLangmuir Isotherm

Langmuir Adsorption Equation


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Langmuir Equation

•From surface chemistry – typical adsorption isotherm – called - Langmuir equation or Langmuir isotherm or Langmuir

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equation or Langmuir isotherm or Langmuir adsorption equation•Relates the coverage or adsorption of molecules on a solid surface to gas pressure or concentration of a medium above the solid surface at a fixedabove the solid surface at a fixed temperature. •Equation - developed by Irving Langmuir in 1916.


Langmuir Equation

1 ααθ

PP⋅+

⋅=

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d tift thi thiithiconstant adsorptionLangmuir the

constant a is solution ain ion concentrator pressure gas theis

surface theof coverage percentage is

α

θP

erature with tempdecreases and adsorptionofstrength in theincreasean with increases


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Langmuir EquationSchlum

berger Public

Value of constant α increases from blue, red, green and brown


End of Introduction

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End of Introduction


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Simulation of Polymer

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Simulation of Polymer Flooding With ECLIPSE

April 11 27NTNU-Seminar

Topics

• Introduction• Principles of Polymer Flooding

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p y g• Polymer chemistry• Polymer implementation in ECLIPSE• How to use in ECLIPSE• Example SimulationExample Simulation

NTNU-Seminar 28April 11

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Principles of Polymer Flooding

• Significant increases in recovery when compared to conventional

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water flooding projects• Reduce the unfavorable effect of

permeability variations• Primary features for effectiveness

R i h t it– Reservoir heterogeneity– Mobility ratio of reservoir fluids

NTNU-SeminarApril 11 29

Polymers

rorw

w o

kkM μ μ⎛ ⎞⎛ ⎞= ⎜ ⎟ ⎜ ⎟

⎝ ⎠ ⎝ ⎠

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• Water soluble polymers– Increase viscosity of displacing fluid– Improving mobility ratio– Increasing displacement efficiency

• To be useful polymer must beTo be useful polymer must be– Effective– Relatively cheap as they are used in high

concentration


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Polymer Chemistry


What are Polymers

• Smaller molecules (monomers) joining together and forming a

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repeating unit called a polymer

• Characteristics– High molecular weight– flexible


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Polymer Examples

• Partially hydrolyzed polyacrylamide• (HPAM)

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( )• Xanthan gum (polysaccharide)• Guar gum (polysaccharide)• Carboxymethylcellulose (CMC)• Hydroxyethylcellulose (HEC)Hydroxyethylcellulose (HEC)• Associating polymers


• Two polymers meet the criteria to be effective and to be economic are:

Polymers

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– Polysaccharides

– Polyacrylamides


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Polysaccharides

• Polymer chemical formulaOHOH

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• It is a xanthan gum• Not very flexible• Molecular weight 5 million!

O

O O

O

O O

Molecular weight 5 million!• Highly rigid• Susceptible to bacterial action


Xanthan Gum Structure

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Acrylamide

• Strictly named acrylic amide– Chemical formula C3H5NO

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– Monomer

– Polymer

2 2CH CH-C-NH=

=

O

CH

C = O

NH2

CH2CH

C = O

NH2

CH

C = O

NH2

CH2 CH2CH

C = O

NH2

CH

C = O

NH2

CH2CH

C = O

NH2

CH

C = O

NH2

CH

C = O

NH2

CH

C = O

NH2

CH2 CH2

– White odorless crystalline solid soluble in water

NH2NH2 NH2NH2NH2NH2NH2 NH2NH2


Polyacrylamide

• Molecular weight 1 – 10 million– Typical molecular weight distribution

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• Flexible molecule• Long thin molecule

– Susceptible to mechanical or shearSusceptible to mechanical or shear breakage

• Immune to bacterial attack


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Hydrolysis of Polyacrylamide

• 0 – 30% hydrolysis achieved by treating with a strong base (eg. NaOH)

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• Both hydrolyzed and unhydrolyzed are

C = O

NH2

C = O

O Na+

Amide Carboxyl

C = O

NH2

C = O

O Na+

Amide Carboxyl

y y y yhighly polar

• Great affinity for water but not oil


Displacement Mechanisms

• Polymers work by increasing effective viscosity of water, also

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reducing mobility

rw o

ro w

kMk

μμ

=


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Displacement Mechanisms

• Term to Consider:– Rheology

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– Solvent– Molecular weight– Hydrolysis– Polymer concentration

T b di d i th f ll i lidTo be discussed in the following slides


Rheology

• Polymers are non-Newtonian fluids and do not strictly increase the

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viscosity of the water• Newtonian fluids deform (flow) when

subjected to shearing force• Resistance to flow is a ratio shearing

force to shear stress called viscosityforce to shear stress, called viscosity τμγ

=μ viscosity

τ shear stress

γ shear rate


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Rheology - Fluid Types

• Newtonian – viscosity remains constant (water, thin oils)

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• Pseudoplastic – decreasing viscosity with increasing shear rate (emulsions polymers)increasing shear rate (emulsions polymers)


Rheology - Pseudoplastic Fluids

• As shearing rate increases, resistance to flow decreases

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• Power law model

nKμ τ=

K and n used to define the flow behavior of the fluid

n < 1 for pseudo plastic fluids

• Exhibits high viscosity at low flow rates and low viscosity at high flow rates


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Rheology - Pseudoplastic Fluids

Linearity at high shear rates

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Linearity at high shear rates“viscosity at infinite shear”

Region of importance

Linearity at low shear rates“viscosity at zero shear rate”


Rheology - Polymer Viscosities

Oil

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ApparentViscosity

Shear Rate (flow velocity)

Water

Polymer

Viscosity of polymers higher than that of water even at high flow rates

Shear Rate (flow velocity)


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Solvents

• In a good solvent • In a poorer solvent

Polymer can be visualized as a fibrous chainSchlum

berger Public

• In a good solvent– Polymer chain

extends to make good contact with solvent

– Gives polymer gel lik

• In a poorer solvent– Minimized contact

with solvent– Reduced

entanglements– More rigid structure

like appearance– Polymer – polymer

entanglement maximized


Solvent - Water

• Distilled water very good solvent• However as salt is added the polar

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pcharge is neutralized and forces extending molecule are reduced

A tApparentViscosity

Salt concentration


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Solvent - Salt Concentration

• Viscosity reduction due to salt concentration more obvious in ionic

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polymers

ApparentViscosity

Salt concentration

Non-ionic polymer


Molecular Weight

• Length of molecules and hence molecular weight is important

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• As the molecules are of fibrous nature, extension and entanglement are important for viscosity increases


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Hydrolysis• Apparent viscosity

increases with the degree of hydrolysis, however as salt is added effect is

ApparentViscosityDistilled

H2O

1000

100

10

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decreased

• CaCl2 (calcium chloride), has a much greater effect than NaCl (sodium chloride) - divalent

• At CaCl2 concentrations > 0 1 wt % viscosity is less

ApparentViscosity

NaCl Conc. %

35% Hydrolysis15% HydrolysisUnhydrolyzed

1000

100

10

10.0001 0.001 0.01 0.1 1 10

% Hydrolysis

10 10 20 30

0.1 wt %, viscosity is less than unhydrolyzed polymer this is not observed with NaCl Apparent

Viscosity

CaCl2 Conc. %

15% Hydrolysis

35% HydrolysisUnhydrolyzed

1000

100

10

10.0001 0.001 0.01 0.1 1 10


Polymer Concentration

• Increase in viscosity due to polymer concentration is initially linear and then quadratic

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quadratic– Initially as concentration increases opportunity

for molecular entanglement increases– At v. low concentrations there is no viscosity

change

A tApparentViscosity

Shear rate

500 ppm polymer25 ppm polymerH2O


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Further Complications!

• Polymer retention and mobility reduction…

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• As polymer is forced through formation there is a significant reduction in polymer concentration due to adsorption and plugging


Polymer Retention

• Reduced permeability caused by polymer retention

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– Polymer forced through cores shows reduction in concentration

– The retention of the polymer in the pore spaces leads to permeability reductionspaces leads to permeability reduction


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Polymer Adsorption

• Adsorption increases with increasing polymer saturation

Schlumberger PublicAdsorption

Polymer concentration


Inaccessible Pore Volume

• Reduced adsorption caused by inaccessible pore volume

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• Only brine passes through small pores, polymer bypasses

• Time of travel of polymer less than expected, velocity is higher, breakthrough sooner than brine


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Entrapment

• Polymer trapped– Large pore openings at one end

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– Small pores at other• Molecule shape

– Elongated while flowing– Coiled when not flowing

• Entrapment is not plugging– Reduces ability of water to flow– Oil can still flow


Residual Resistance

• Adsorption and entrapment are only partially reversible

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• Effect of polymer can be seen long after polymer injection has taken place

100

%P bilit

80Original

perm. reduction

ResidualPermeabilityReduction

Pore Volume of Fluid

20

10.01 0.1 1 10 100

40

60 Residualperm. reduction

Polymerflow

Brineflow


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Shear Degradation

• Breakup of polymer chain as shear rate increases

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– Vicious shear is less than viscoelastic shear

• Presence of salts increases susceptibility to shear degradation


Selection of Reservoir for Polymer Injection

• Mobility poor (2 – 20)– >20 economics are likely to be poor

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– ~ 1 then little to be gained• Significant permeability distribution• Will help if high water cut due to

– Water coning– High perm zone– High viscosity oil (up to 300 cP)


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Parameters

• Reservoir temperature < 250-300 °F• Reasonably high mobile oil So

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y g o

• Not useful in fractured/vuggy reservoirs


Modifications for Polymers

• Modifications to the water equation required to account for polymers

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– Accumulation of polymer– Adsorption of polymer– Effect of brine


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Polymer Equations

• Water Equation

( )w rwd VS Tk P gD Qδ ρ⎡ ⎤⎛ ⎞

= − +⎢ ⎥⎜ ⎟ ∑

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• Polymer Equation

( )w w z wr w w w eff k

P gD Qdt B B B R

δ ρμ

= − +⎢ ⎥⎜ ⎟⎢ ⎥⎝ ⎠ ⎣ ⎦

∑

*S S S

( )* 1w p rw p

r a w w z w pr w w p eff k

V S C Tk Cd d V C P gD Q Cdt B B dt B R

φρ δ ρφ μ

⎡ ⎤⎛ ⎞ ⎛ ⎞−+ = − +⎜ ⎟ ⎢ ⎥⎜ ⎟⎜ ⎟ ⎝ ⎠ ⎢ ⎥⎝ ⎠ ⎣ ⎦

∑

Adsorption term

Polymer concentration

• Brine Equation

( )w n rw nw w z w n

r w w s eff k

d VS C Tk C P gD Q Cdt B B B R

δ ρμ

⎡ ⎤⎛ ⎞= − +⎢ ⎥⎜ ⎟

⎢ ⎥⎝ ⎠ ⎣ ⎦∑

w w dpvS S S= − Polymer concentration

Rock formation vol. factor


Nomenclature denotes dead pore space in each grid cell

C denotes the polymer adsorption concentration denotes the mass density of the formation

denotes the porosity

dpv

ap

r

S

ρφ

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denotes the porosity w

φρ denotes the water density

denotes the sum over all neighbouring cellsR denotes the relative permeability reduction factor for the aqueous phase due to polymer retentio

k

∑

n denotes the effective viscosity of the water (a=w), polymer (a=p) and

salt (a=s). is the cell center depth,B are the rock and water formation volumes

eff

z

r w

DBT

αμ

the transmissibility is the water relative permeability is the water saturation

is the block pore volume is the water production rate is the wa

rw

w

w

w

kSVQP ter pressure

is the gravity accelerationg


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Numerical Stability

• Equations are solved implicitly– Removes problems that could be

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caused by large changes in aqueous properties over a time step

• IMPES solution algorithm cannot be used with the Polymer optionused with the Polymer option


Fluid Viscosities

• Need to account for the viscosity change due to presence of:

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– Salt– Polymer

• Need to account for:– Physical dispersion at leading edge of

the slug– Fingering effects at rear edge of slug

• Use Todd-Longstaff technique to calculate effective fluid viscosities


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Aqueous Fluid Viscosities – Effective Polymer Viscosity

• Viscosity change due to polymers and salt• Effective viscosity estimated using Todd –

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Longstaff technique

• Mixing parameter ω models degree of

( ) 1,p eff m p pC

ω ωμ μ μ −=

Polymer concentration in solution

Viscosity at max polymer concentration(injected polymer concentration)

Mixing parameter ω models degree of segregation between water and injected polymer

ω = 1 Polymer solution and water fully mixed

ω = 0 Polymer segregated from the water


Brine Option

• Effective polymer viscosity and partially mixed water viscosity terms

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hold• Injection salt concentration required

to calculate maximum polymer viscosity (μp)The effective salt component• The effective salt component viscosity is set to effective water viscosity


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Polymer Adsorption

• Treated as instantaneous effect• Creates stripped water bank at leading

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edge• Desorption may occur as slug passes• User specified adsorption isotherm• Tabulate (look up table) PLYADS

– local polymer concentration in solutionp yvs.

– saturated concentration adsorbed by rock


PLYADS - ExamplePLYADS--polymer polymer concentration concentration

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--concentration concentration -- lb/stb adsorbed by rock-- lb/lb

0.0 0.0020.0 0.01070.0 0.010 /70.0 0.010 /


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Two Adsorption - Desorption Models

1. Adsorption-Desorption - Each cell retraces adsorption isotherm as

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polymer concentration rises and falls

2. Adsorption-NO Desorption Adsorbed concentration on rock may not decrease with timemay not decrease with time


Non-Newtonian Rheology – 2 Models

• Model 1– Shear thinning reduces the polymer viscosity

at high flow rates

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at high flow rates

• Model 2– Hershel-Buckley used to model shear thinning

and thickening, yield stress as a function of polymer concentrationpolymer concentration


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PROPS keywordsSchlum

berger Public


Injection Wells

• WPOLYMER: Defines the polymer and salt injection streams

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• Note: wells are not allowed to cross-flow when polymer flood model is used – gone in 2011.1


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E amples of Pol mer Flooding Schlumberger Public

Examples of Polymer Flooding Simulations


Case 1 – Field Units

• Polymer injection into our water flooded reservoir.

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• Polymer concentration 10.5 lbs/stb• Polymer solution viscosity = 3.4 cP


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Oil Production Rate???Schlum

berger Public


What is happening???

Question to be Answered:

How does Polymer flooding

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How does Polymer flooding compare to normal water

flooding?


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Case 2

• Switch to initial (prior to water flood) oil saturation reservoir.

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• Case 2a: Inject water only – 2000 days

• Case 2b: Inject polymer for 360 days, inject water for 1640 days.

• Runs terminate when oil production rate < 30 stb/day

• Limited polymer adsorptionApril 11 NTNU-Seminar 79

Comparison of Water Flood with Polymer Flood

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RF for water flood

RF for polymer flood


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Polymer Production Rate (lb/day)Schlum

berger Public


Economics of Polymer Flooding

• Polymer cost = $2 / lb• Polymer injected = 756,000 lbs

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y j ,• Cost of polymer = $1.5 Million• Incremental oil produced

(incremental over water flood) = 35,000 Stb

• Income from oil production = $3.5 Million

• Profit = $2 Million = 11 Million NOKApril 11 NTNU-Seminar 82

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E d f Si l ti f P l Schlumberger Public

End of Simulation of Polymer Flooding Lecture

83April 11 NTNU-Seminar

Simulation of Surfactant

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Flooding With ECLIPSE


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Surfactant Flooding

•Also goes by the names:•Chemical Flooding

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g•Surfactant-Polymer Flooding•ASP Flooding – Alkali-Surfactant-Polymer Flooding


Surfactants

•Surfactants are wetting agents that lower the surface tension of a liquid, allowing easier spreading and lower the interfacial

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easier spreading, and lower the interfacial tension between two liquids.•When the interfacial tension is reduced the residual oil decreases and the capillary pressure decreases.Wh th i t f i l t i i d d th•When the interfacial tension is reduced the

capillary number NCA increases – see next slide.


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Capillary Number – NCA or Ca•Capillary number represents the relative effect of viscous forces versus surface pkN Δ

=

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forces versus surface tension acting across an interface between a liquid and a gas, or between two immiscible liquids.•k = permeability•Δp/L = pressure gradient

σμ

σ

vN

orL

N

CA

CA

=

=

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Δp/L = pressure gradient along capillary•v = velocity

•σ = interfacial tension between fluids

Capillary Number

•Typical water flood capillary number are 10-7

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•For an effective surfactant flood –capillary number = 10-4 to 10-3

•Interfacial tension reduction of 1000 to 10,000 necessary


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History of Surfactant Research and Applications

•Original Patent – 1929 De Groot –claiming water-soluble surfactants as

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an aid to improved oil recovery.•1962 – Gogarty and Olson of Marathon Oil Co. – patent based on field trial where used petroleum sulfonates along with a chemical slug containingalong with a chemical slug containing hydrocarbons, water, electrolyte, and co-surfactants.


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History of Surfactant Research and Applications

•There have been twenty-seven known Alkaline Surfactant Polymer, Surfactant Polymer or Alkaline Polymer projects

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Polymer or Alkaline Polymer projects around the world since 1980. •They have taken place in Alberta, California, China, Colorado, Indonesia, Louisiana, Oklahoma, Venezuela, and Wyoming.Th d f bli ti i t•Thousands of publications exist on

Surfactant/Chemical Flooding


Past Surfactant Flooding –Reasons for Field Scale Failure

•Sensitivity to oil price• Large up-front investment

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• Unpredictable return on investment• High surfactant concentration• Salinity optimization required• Optimum salinity shift in the formation• Potential emulsion block• Potential emulsion block• Economic feasibility


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Source of Cost Data

•Oil Chem Technologies, Inc.•12822 Park One Drive

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•Sugar Land, TX 77478•www.oil-chem.com


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Complex Process

•Surfactant flooding involves:• Multi-phase behavior

Adsorption

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• Adsorption• Salinity issues• Micelles• Surface tension• Relative permeability and capillary pressure

changesVi it h• Viscosity changes

• Wetability changes• Diffusion


Complex Process

•To understand all the details takes weeks or months

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•And a knowledge of physical chemistry, etc.•We will look at a few basic concepts•Then look at ECLIPSE 100 Advanced Options implementation


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Micellar/Polymer

•Most process are Micellar/Polymer –that is Surfactant solution in injected

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into the reservoir followed by a Polymer solution for mobility control•We will initially look at just Surfactant flooding – since you have already seen Polymer floodingPolymer flooding


Basic Idea

•Surfactants (surface active agent) can be added to injected water to decrease

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the residual oil saturation.•n% PV slug of surfactant solution is injected into reservoir often followed by polymer mixture for mobility controlcontrol.


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Description of the Micellar/Polymer Process

•Most situations – tertiary displacement at the end of water flood.

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•Oil saturation is Sorw.•Specific volume – primary slug – of micellar solution is injected•Volume of slug is 3% to 30% of flood pattern PV•Micellar solution has very low IFT with residual crude oil – mobilizes the trapped oil – forms an oil bank – ahead of the slug



•Micellar slug – also low IFT with brine – displaces brine as well as oil

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•Both oil and water flow in the oil bank•Oil production occurs after oil bank breaks through


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•Micellar/Polymer process – can be applied as secondary recovery

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process•Micellar solution – designed so –favorable mobility displacement•Potential to increase both volumetric sweep efficiency and microscopicsweep efficiency and microscopic displacement efficiency


Basic Idea

•Surfactant solution can be injected as tertiary recovery process.

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Basic Idea

•Surfactants (surface active agent) can be added to injected water to decrease the residual oil saturation

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residual oil saturation.•If surfactant concentration is large enough – oil + water system can be single phase –surfactant is expensive so this is not a viable process.L t ti f f t t d 3•Low concentration of surfactant produces 3

phase mixture – oil + micro-emulsion + water – with low interfacial tension


Typical Surfactant or Micellar Solution Compositions

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Basic Theory

•Surfactants reduce the interfacial tension between oil and water by

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adsorbing at the liquid-liquid interface.•Examples of such aggregates are called vesicles and micelles.• The concentration at which surfactants begin to form micelles issurfactants begin to form micelles is known as the critical micelle concentration or CMC.


IFT as a Function of Surfactant Concentration

CMC is critical micelle concentration

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Basic Theory

•When micelles form in water, their tails (hydrocarbon portion – non polar)

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form a core that can encapsulate an oil droplet, and their (ionic/polar) heads form an outer shell that maintains favorable contact with water.


MicelleA micelle - the lipophilic ends of the surfactant molecules dissolve in the oil, while the hydrophilic charged ends remain outside, shielding the

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rest of the hydrophobic micelle

Hydrophilic head


Aqueous Solution

Hydrophobic tail

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Idea Phase Behavior of Micro-emulsion on Ternary Diagram

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Effect of Salinity on Micro-emulsion Phase Behavior

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Names of Surfactant Phase Behavior Systems

•(II –) system – oil is upper phase at low salinity (also called Upper Phase)

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•(II +) system – brine is lower phase at high salinity (also called Lower Phase)•(III) system – 3 phase system with oil + micro emulsion + brine at middle salinity (also called Middle Phase)salinity (also called Middle Phase)


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IFT as a Function of Salinity

Optimum is the

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Optimum is the 3 phase “ Middle” system


N Fi ld T i l Schlumberger Public

Numerous Field Trials3 Examples from Marathon,

Exxon, and Conoco


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ECLIPSE 100 Advanced Options Treatment of Surfactant Flooding


ECLIPSE Technical Description –Surfactant Flooding Chapter

•“The ECLIPSE Surfactant model does not aim to model the detailed

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chemistry of a surfactant process, but rather to model the important features of a surfactant flood on a full field basis.”


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Surfactant Flooding Overview1. Inject surfactant water solution into

reservoir2. Surfactant concentration solved by

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yconservation equation in the water phase.

3. Interfacial tension – table look-up as a function of surfactant concentration

4. Capillary number calculated as a function of interfacial tension

5. Oil and water phase relative permeability interpolated as function of capillary number


Surfactant Flooding Overview

6. Water-oil capillary pressure reduced as a function of interfacial tension (surfactant concentration)

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concentration)7. Water viscosity changed as a function of

surfactant concentration.8. Surfactant adsorbs onto the reservoir

rock.9. Wettability of the rock changes as a

function of amount of surfactant adsorbed.


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Details of ECLIPSE Surfactant

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ModelTheory and equations


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Brief Overview of Surfactant Keywords


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PROPS KeywordsSchlum

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SURFADDW Concentration of adsorbed surfactant versus the fraction of the oil-wet and water-wet saturation functions (Optional)

Surfactant Conservation Equation

•The distribution of injected surfactant is modeled by solving a conservation

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equation for surfactant within the water phase. •The surfactant concentrations are updated fully-implicitly at the end of each time-step after the oil water andeach time-step after the oil, water and gas flows have been computed.


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Surfactant Conservation Equation

•The surfactant is assumed to exist only in the water phase, and the input

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to the reservoir is specified as a concentration at a water injector.


Calculation of the Capillary Number

•The capillary number is a dimensionless group that measures the ratio of viscous forces to

ill f

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capillary forces. •The capillary number is given by:

unitc CSTgradPK

N⋅

=

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ST

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Calculation of the Capillary Number

•where•K is the permeability

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•P is the potential•ST is the interfacial tension (see SURFST Keyword)•Cunit is conversion factor•|K grad P | is calculated as

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222 )()()( zzyyxx gradPKgradPKgradPKgradPK ⋅+⋅+⋅=⋅

Example Calculations of Capillary Number

Typical water flood

metric units

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K grad P Surface Tension Cunit Nc Log10(Nc)

mD bars/meters N/m 9.87E-11

500 5 1 2.47E-07 -6.61

0.1 2.47E-06 -5.61

0 01 2 47E-05 -4 61

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Effective Surfactant flood

0.01 2.47E 05 4.61

0.001 2.47E-04 -3.61

0.0001 2.47E-03 -2.61

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Surface Tension Table

•The surface tension is a tabulated function of the surfactant

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concentration.


Relative Permeability Model

•The Relative Permeability model is essentially a transition from immiscible relative permeability curves at low capillary

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relative permeability curves at low capillary number to miscible relative permeability curves at high capillary number. •User supplies table that describes the transition as a function of log10 (capillary number)number).


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Capillary Pressure

•oil water capillary pressure

)(CST

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( )

ionconcentrat zeroat tension surface theis )0(ionconcentrat surfactantcurrent at the tension surface theis )(

)0()(

=

==

surf

surf

surf

surfwcowcow

CSTCST

where

CSTCST

SPP

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Water PVT Properties

•Surfactant modifies the viscosity of the pure water phase.

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•Multiplies the viscosity entered with the PVTW Keyword


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Treatment of Adsorption -SURFADS

•The adsorption of surfactant –instantaneous

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• Quantity adsorbed - function of the surrounding surfactant concentration. •User - supply an adsorption isotherm -function of surfactant concentration


Modeling the Change to Wettability

•This feature enables the modeling of changes to wettability of the rock due to the accumulation of surfactant on the rock (adsorption).

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surfactant on the rock (adsorption). •It is activated by using the SURFACTW keyword (RUNSPEC)•To use this option sets of both oil-wet and water-wet relative permeabilities must be input.•An interpolation between these 2 sets of curves is a function of the concentration of adsorbeda function of the concentration of adsorbed surfactant.


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Exercise on Surfactant Flooding

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gSimulations



In a water flooded reservoir, how

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In a water flooded reservoir, how does a low adsorption surfactant’s

performance compare to a high adsorption surfactant?


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Surfactant Flooding Program –Metric Units

• Inject water 500 Sm3/day -100 days –preflush

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• Inject surfactant solution - 500 Sm3/day – 10.5 kg/m3 – 1000 days

• Inject water 500 Sm3/day -5000 days


Surfactant Flooding Cases

• Case 1: No adsorption onto the rock• Case 2: Normal adsorption onto the

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prock


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Comparison of RF – Surfactant Flooding Cases

No surfactant adsorption

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adsorption

With surfactant


adsorption

Comparison of Surfactant Flooding Cases – Oil Production Rate

No surfactant

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adsorption

With surfactant


adsorption

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Comparison of Surfactant Flooding Cases –Surfactant Production Rate

No surfactant adsorption

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adsorption


With surfactant adsorption

Economics – Metric Units

• Surfactant cost = $3.00 per kg• Oil price = $629 per m3

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p p• Surfactant injected = 5,096,000 kg• Oil production (no adsorption) =

729,000 m3

• Oil production (with adsorption) = ( )200,000 m3


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Economics

• Cost of injected surfactant = $15 Million• Income from oil (no adsorption) = $458

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( p )Million

• Income from oil (with adsorption) = $125 Million

• Process makes money even with adsorption.


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END of Simulation of Surfactant Flooding Lecture


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Simulation of ASP (Alkaline-Surfactant-Polymer) Flooding with

ECLIPSE


ASP Flooding

•Also goes by the name: Chemical Flooding

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•ASP Flooding – Alkali-Surfactant-Polymer Flooding•Starts with the injection of alkali agents to reduce interfacial tension (IFT) and residual oil saturation

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(IFT) and residual oil saturation•OR – injected combined slug of A+S+P

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Links Between ASP Flooding and Surfactant Flooding and Polymer Flooding

•We have previously seen Surfactant Flooding and Polymer Flooding

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Flooding and Polymer Flooding.•The situation here is very similar – we will concentrate on the differences when we inject an alkali into the reservoir.

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Definition of Alkali

•Alkali (from Arabic: Al-Qaly ) is a basic, ionic salt of an alkali metal or

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alkaline earth metal element. •Alkalis are best known for being bases that dissolve in water. Bases are compounds with a pH greater than 7.

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Alkai

•Alkalis are all Arrhenius bases, which form hydroxide ions (OH-) when dissolved in water.

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•Common properties of alkaline aqueous solutions include:

• Moderately-concentrated solutions (over 10−3 M) have a pH of 10 or greater. Concentrated solutions are caustic (causing chemical burns).

• Alkaline solutions are slippery or soapy to the t h d t th ifi ti f th f tt id

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touch, due to the saponification of the fatty acids on the surface of the skin.

Basic Salts

•Most basic salts are alkali salts, of which common examples are:

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• sodium hydroxide (often called "caustic soda")

• potassium hydroxide (commonly called "caustic potash")

• lye (generic term, for either of the previous two, or even for a mixture)

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two, or even for a mixture)• calcium carbonate (sometimes called "free

lime")• magnesium hydroxide is an example of an

atypical alkali since it has low solubility in water.

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ASP Flooding - Overview

•Synergistic chemical flooding process using alkali, surfactant, and polymer

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•Synergistic = working together where different entities cooperate advantageously for a final outcome•Oil recovery can be greatly improved by synergism of 2 or 3 chemicals

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by synergism of 2 or 3 chemicals together

ASP Flooding - Overview

•Quantity of expensive surfactant used – reduced 10 times

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•Instead use cheaper alkali agent•ASP flooding – used to recovery acid oil•Typical alkali (NaOH or Na2CO3) is

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much cheaper that surfactant

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ASP Flooding - Process

•ASP chemical slug combining high concentration of Alkali + low

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concentration of Surfactant + low concentration of Polymer is injected in to the reservoir•Alternate Process – A + S injected followed by Polymer slug for mobility

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followed by Polymer slug for mobility control.

ASP Flooding - Mechanisms

•Reducing interfacial tension (IFT)• Reaction between alkali and acid

t i il d i it f t t

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component in oil produce in-situ surfactant• Reduces the IFT and residual oil saturation• Surfactant further decreases IFT• Polymer increases slug (aqueous phase)

viscosity for mobility control – enlarge sweeping volume

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p g

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Typical ASP Flood - 1

•Chemicals used in the ASP flood are an alkali (NaOH or Na2CO3), a

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surfactant and a polymer. •The alkali (1 to 2%) washes residual oil from the reservoir mainly by reducing interfacial tension between the oil and the water

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the oil and the water.


•The surfactant (0.1 to 3 %) is mixed with the alkali and enhances the

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ability of the alkaline to lower interfacial tension. •The polymer (1,000 to 100,000 ppm) injected after the AS slug is added to improve sweep efficiency

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improve sweep efficiency.

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•The ASP chemical slug is injected first at approximately 30% pore volume.

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•The polymer slug (approximately 25% pore volume) is injected next to push the ASP solution and maintain mobility control. Water is then injected to continue

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•Water is then injected to continue pushing the ASP and polymer slugs to the economic limit.


•Wells are drilled at 5 acre spacing.•Estimated ASP process oil recovery is

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p y15 to 25 %.

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ECLIPSE 100 T t t f “Th Schlumberger Public

ECLIPSE 100 Treatment of “The Alkaline Model”

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Sections To Be Discussed -1

•Advanced ECLIPSE Options ASP Approximation

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•Alkaline conservation equation•Alkaline Concentrations Update•Treatment of adsorption•Treatment of desorption

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•Alkaline effect on water-oil surface tension

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Sections To Be Discussed - 2

•Alkaline effect on surfactant/polymer adsorption

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•ASP Example

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Advanced ECLIPSE Options ASP Approximation

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The Alkaline Model –ECLIPSE Technical Description Chapter 3

•Alkaline flooding requires the injection of alkaline chemicals (lye or caustic

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alkaline chemicals (lye or caustic solutions, that is high pH solutions) into a reservoir that react with petroleum acids to form in-situ surfactants that help release the oil from the rock by reducing interfacial tension changing the rock

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interfacial tension, changing the rock surface wettability, and spontaneous emulsification.


•When used in conjunction with surfactant and polymer to perform an

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Alkaline-Surfactant-Polymer (ASP) flooding, the alkaline can reduce the adsorption of both surfactant and polymer on the rock surface, therefore enhancing the effectiveness of the

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enhancing the effectiveness of the surfactant and polymer drive.

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•ECLIPSE provides a simplified model that does not take into account the in-situ surfactant creation and the phase behavior

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surfactant creation and the phase behavior.•The inject of only alkaline will not mobilize residual oil – one must inject the alkaline along with some surfactant to do an EOR flood.O i j t f t t th th

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•Once you inject some surfactant then the alkaline will help the surfactant reduce the IFT.

RUNSPEC

OIL

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WATER

POLYMERSURFACTALKALINE

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FIELD

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Alkaline Effect on Water-Oil Surface Tension

•Model the effect of alkaline on the water-oil surface tension as a combined effect with surfactant by

dif i th t il f t i f ll

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modifying the water-oil surface tension as follows:

andion concentrat surfactant as tension surface is )(

)()(

surfwo

alkstsurfwowo

Cwhere

CAC

σ

σσ =

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keyword) (ALSURFSTion concentrat alkalineat multiplier tension surface theis )(

keyword)(SURFSTion concentratalkaline zero

alkst CA

Alkaline Effect on Surfactant/Polymer Adsorption

•The alkaline can reduce the adsorption of both surfactant and

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polymer on the rock surface.

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PROPS SectionSchlum

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Examples of ASP Flooding

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Examples of ASP Flooding Simulations

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What is the importance of the

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pPolymer in the ASP Slug Injection and in the drive water injection?

Water Flooded Reservoir


ASP / AS Flood in Sector Model• Special designed solution of Alkaline

+Surfactant + Polymer is created.C S f Schlum

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• Case 1: ASP injected for 1000 days followed by 1000 days of polymer injection (drive water) – for mobility control

• Case 2: AS (no P) injected for 1000Case 2: AS (no P) injected for 1000 days followed by 1000 day of water injection only – no polymer in slug or drive water


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Case 1: Our Injection Well Injects A+S+P

-- inject 1 wt % alkalineWALKALIN--well alkaline injection--name concentration lb/stb

I 3 5 /

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I 3.5 //-- inject 3 wt % surfactantWSURFACT--well surfactant injection--name concentration lb/stb

I 10.5 //

-- inject 3 wt % polymer


WPOLYMER--well polymer injection Salt--name concentration lb/stb concentrations

I 10.5 0.0 //

FOE (RF) for ASP / AS Flood Simulation

ASP followed by

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Polymer Solution


AS followed by Water

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Oil Production Rate

ASP followed by

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Polymer Solution



Production of Alkaline

ASP followed by

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Polymer Solution



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Economics

• Polymer cost = $21 Million• Oil Production (Polymer case) =

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( y )272,000 stb

• Oil Production (no Polymer case) = 148,000 stb

• Incremental income from injecting $polymer = $12 Million

• Need to find cheaper polymer!!!



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What is the effect of the Alkaline in the ASP Flood?

Water Flooded Reservoir


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What do we know about Alkaline in an ASP Flood.

• The presents of Alkaline lowers the water-oil IFT an additional amount.

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• As Alkaline adsorbs on the rock, it reduces the adsorption of both surfactant and polymer on the rock.


ASP / SP Cases

• Case 1: Standard ASP flood – 1000 days of ASP injection followed by

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1000 days of polymer + drive water injection.

• Case 2: SP flood (no Alkaline) – 1000 days of SP injection followed by 1000 days of polymer + drive waterdays of polymer + drive water injection.


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FOE Comparison

Standard ASP followed

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by Polymer

SP followed by Polymer (no A)


Oil Production Rate

Standard ASP followed

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by Polymer



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Surfactant Adsorbed in Block (5,1,1)Schlum

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Standard ASP followed by Polymer

Economics

• Cost of Alkaline = 0.30 / lb• Amount of Alkaline injected in Case 1

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j= 1,750,000 lbs

• Cost of injected Alkaline = $525,000• Incremental oil produced Case 1

(with Alkaline injection) = 88,000 stb• Net profit (Case 1) = $8.3 Million• Injection of Alkaline – positive effect


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END of ASP Flooding Sim lation Schlumberger Public

END of ASP Flooding Simulation Lecture

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Questions?


modeling polymer flooding, surfactant flooding and...

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